1. Field of the Invention
The present invention relates to monitoring performance and to failure prediction of electrical submersible pumps in wells.
2. Description of the Related Art
Submersible pumps have been used in wells for oil production at various depths and flow rates. The pumps are typically electrically powered and referred to as Electrical Submersible Pumps (ESP's). ESP's were one of several forms of what is known as artificial lift. ESP's were located in tubing in the well and provided a relatively efficient form of production.
An ESP system used in oil production included surface components at the production wellhead or platform and subsurface components located in production tubing or casing at the level of producing formations in the well. Surface components included a motor controller and surface cables and transformers for power transfer to the subsurface components downhole. Subsurface components in the well included a pump, pump motor, fluid seals and power supply cables.
The downhole ESP pumps were immersed in the well fluids being pumped for production at the operating depths in the well and drove formation fluids to the surface with power supplied from the electrically powered pump motor which received operating power from the surface over the power supply cables.
During production from the formation, mineral deposits from the formation fluid occurred in and around the ESP's, well tubing and other subsurface equipment, and have caused recurrent problems. The mineral deposits were known as scale. One of the common failure reasons in ESP assemblies resulted from scale build-up in the pump stages, where scale gradually formed around the impeller vanes and eventually blocked fluid flow. Scale deposits led to a gradual decrease of the pump efficiency until pump failure eventually occurred.
Problems with scale and other subsurface conditions as well as extended service eventually led to failure of the downhole ESP components, usually the pump. The causes and reasons of ESP component failure were usually analyzed after the system had been pulled out or extracted from the well. The analysis commonly used after the ESP had been removed from the well was a detailed DIFA (Dismantle Inspection & Failure Analysis) process where each component of the ESP assembly was carefully analyzed for an understanding of the nature of the failure. Experience has shown that generally more than 20% of failure causes were attributed to motor failure.
As noted, however, this form of failure analysis could only be performed after the failure occurred, and after the downhole or subsurface ESP components had been extracted from the well. Both the ESP failure and its removal from the well caused production from the well to be stopped. Production from the well was only resumed when a replacement ESP subsurface system could be installed in the well. Production from the well was thus interrupted for the time required for scheduling a workover rig and its transport to the well, in addition to the time for installation of a replacement ESP subsurface system.